Methods and Apparatus for Determining Downhole Parameters

ABSTRACT

Apparatus and methods for determining downhole fluid parameters are disclosed herein. An example method includes deploying a downhole apparatus into a wellbore. The downhole apparatus includes a sensor having a heater and a temperature sensor. The method also includes traversing the downhole apparatus through the wellbore and obtaining a first response with the sensor in a first position of the wellbore. The method also includes obtaining a second response with the sensor in a second position of wellbore and determining a presence of a boundary between the first and second positions based on the first and second responses.

RELATED APPLICATIONS

This patent claims the benefit of U.S. Provisional Patent ApplicationSer. No. 61/496,180, entitled “System and Method for DeterminingDownhole Fluid and Borehole Parameters,” which was filed on Jun. 13,2011, and is incorporated herein by reference in its entirety.

BACKGROUND

A well may be drilled through a subterranean formation to extracthydrocarbons.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

An example method in accordance with the teachings of this disclosureincludes deploying a downhole apparatus into a wellbore. The downholeapparatus includes a sensor having a heater and a temperature sensor.The downhole apparatus also includes traversing the downhole apparatusthrough the wellbore and obtaining a first response with the sensor in afirst position of the wellbore. The downhole tool also includesobtaining a second response with the sensor in a second position ofwellbore and determining a presence of a boundary between the first andsecond positions based on the first and second responses.

An example method in accordance with the teachings of this disclosureincludes determining a first thermal property of a first fluid at afirst wellbore position via a sensor of a downhole tool. The sensorincludes a heater and a temperature sensor. The method also includesdetermining a second thermal property of a second fluid at a secondwellbore position via the sensor and comparing the first and secondthermal properties to identify a difference therebetween associated witha boundary.

An example method in accordance with the teachings of this disclosureincludes determining a first thermal property of a first fluid at afirst wellbore position via a sensor of a downhole tool. The sensorcomprising a heater and a temperature sensor. The method also includescomparing the first thermal property with thermal properties ofreference fluids and determining a fluid type of the first fluid basedon the comparison.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of methods and apparatus for determining downhole parametersare described with reference to the following figures. The same numbersare used throughout the figures to reference like features andcomponents.

FIG. 1A illustrates an example system in which embodiments of methodsand apparatus for determining downhole parameters can be implemented.

FIG. 1B illustrates various components of an example device that canimplement embodiments of the methods and apparatus for determiningdownhole parameters.

FIG. 1C illustrates various components of the example device of FIG. 1Bthat can implement embodiments of the example methods and apparatus fordetermining downhole parameters.

FIG. 1D illustrates various components of another example device thatcan implement embodiments of the methods and apparatus for determiningdownhole parameters.

FIG. 2A illustrates various components of an example device that canimplement embodiments of the methods and apparatus for determiningdownhole parameters.

FIG. 2B illustrates various components of the example device of FIG. 2Athat can implement embodiments of the methods and apparatus fordetermining downhole parameters.

FIG. 2C illustrates various components of the example device of FIG. 2Athat can implement embodiments of the methods and apparatus fordetermining downhole parameters.

FIG. 2D illustrates various components of another example device thatcan implement embodiments of the methods and apparatus for determiningdownhole parameters.

FIG. 2E illustrates various components of yet another example devicethat can implement embodiments of the methods and apparatus fordetermining downhole parameters.

FIG. 3 is a graph depicting sensor measurements taken using the exampledevice of FIG. 2B.

FIG. 4A illustrates various components of an example device that canimplement embodiments of the methods and apparatus for determiningdownhole parameters.

FIG. 4B illustrates various components of an example device that canimplement embodiments of the methods and apparatus for determiningdownhole parameters.

FIG. 5A is a graph illustrating sensor measurements.

FIG. 5B is another graph illustrating sensor measurements.

FIG. 6 is a graph of sensor measurements and fluid flow based on thesensor measurements.

FIG. 7 illustrates various components of an example device that canimplement embodiments of the methods and apparatus for determiningdownhole parameters.

FIG. 8 illustrates various components of an example device that canimplement embodiments of the methods and apparatus for determiningdownhole parameters.

FIG. 10 illustrates example method(s) for determining downholeparameters in accordance with one or more embodiments.

FIG. 11 illustrates example method(s) for determining downholeparameters in accordance with one or more embodiments.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides manydifferent embodiments or examples for implementing different features ofvarious embodiments. Specific examples of components and arrangementsare described below to simplify the present disclosure. These are, ofcourse, merely examples and are not intended to be limiting. Inaddition, the present disclosure may repeat reference numerals and/orletters in the various examples. This repetition is for the purpose ofsimplicity and clarity and does not in itself dictate a relationshipbetween the various embodiments and/or configurations discussed.Moreover, the formation of a first feature over or on a second featurein the description that follows may include embodiments in which thefirst and second features are formed in direct contact, and may alsoinclude embodiments in which additional features may be formedinterposing the first and second features such that the first and secondfeatures may not be in direct contact.

Although some example fluid sensing systems disclosed herein arediscussed as being positioned on treatment tools of a coiled tubingsystem, other examples are employed with and/or without treatment tools.For example, a fluid sensing element may be employed apart from thecoiled tubing system. Thus, in some examples, the fluid sensing systemmay be deployed by a drill pipe, a drill string or any other suitableconveyance device.

The examples disclosed herein relate to methods and apparatus foridentifying formation and/or fluid properties. In some examples, theformation properties (e.g., boundary layers, boundaries) may beidentified by measuring fluid properties at different positions within awellbore. The fluid properties may be thermal properties of the fluid,velocities of the fluid, etc., and the sensor used to measure the fluidproperties may include a heater and a temperature sensor. In operation,a boundary (e.g., an interface between different fluids within thewellbore) may be identified based on differences of fluid propertiesbetween the different positions. Using the examples disclosed herein,the identified properties may be used to generate a profile and/or modelof the formation.

In some examples, characteristics and/or types of the fluid measured maybe determined using the examples disclosed herein. The fluid type(s) maybe associated with gas, mud, oil, water and/or brine. In operation, aresponse and/or thermal properties of the measured fluid may be comparedto responses and/or thermal properties of reference fluids to identifysimilarities and the measured fluid type. Using the examples disclosedherein, the identified fluid types may be used to generate a profileand/or model of the formation.

FIG. 1A is a schematic depiction of a wellsite 100 with a coiled tubingsystem 102 deployed into a well 104. The coiled tubing system 102includes surface delivery equipment 106, including a coiled tubing truck108 with reel 110, positioned adjacent the well 104 at the wellsite 100.The coiled tubing system 102 also includes coiled tubing 114. In someexamples, a pump 115 is used to pump a fluid into the well 104 via thecoiled tubing. With the coiled tubing 114 run through a conventionalgooseneck injector 116 supported by a mast 118 over the well 104, thecoiled tubing 114 may be advanced into the well 104. That is, the coiledtubing 114 may be forced down through valving and pressure controlequipment 120 and into the well 104. In the coiled tubing system 102 asshown, a treatment device 122 is provided for delivering fluids downholeduring a treatment application. The treatment device 122 is deployableinto the well 104 to carry fluids, such as an acidizing agent or othertreatment fluid, and disperse the fluids through at least one injectionport 124 of the treatment device 122.

The example treatment device 122 is optional and its use will depend onthe various applications. The coiled tubing system 102 of FIG. 1A isdepicted as having a fluid sensing system 126 positioned about theinjection port 124 for determining parameters of fluids in the well 104.The fluid sensing system 126 is configured to determine fluidparameters, such as fluid direction and/or velocity. In other examples,other downhole parameters are determined.

In some examples, the coiled tubing system 102 includes a logging tool128 for collecting downhole data. The logging tool 128 as shown isprovided near a downhole end of the coiled tubing 114. The logging tool128 acquires a variety of logging data from the well 104 and surroundingformation layers 130, 132 such as those depicted in FIG. 1A. The loggingtool 128 is provided with a host of well profile generating equipment orimplements configured for production logging to acquire well fluids andformation measurements from which an overall production profile may bedeveloped. Other logging, data acquisition, monitoring, imaging and/orother devices and/or capabilities may be provided to acquire datarelative to a variety of well characteristics. Information gathered maybe acquired at the surface in a high speed manner, and, whereappropriate, put to immediate real-time use (e.g. via a treatmentapplication). Some examples do not employ the logging tool 128.

With reference still to FIG. 1A, the coiled tubing 114 with thetreatment device 122, the fluid sensing system 126 and the logging tool128 thereon is deployed downhole. As these components are deployed,treatment, sensing and/or logging applications may be directed by way ofa control unit 136 at the surface. For example, the treatment device 122may be activated to release fluid from the injection port 124; the fluidsensing system 126 may be activated to collect fluid measurements;and/or the logging tool 128 may be activated to log downhole data, asdesired. The treatment device 122, the fluid sensing system 126 and thelogging tool 128 are in communication with the control unit 136 via acommunication link (FIGS. 1B-1D), which conveys signals (e.g., power,communication, control, etc.) therebetween. In some examples, thecommunication link is located in the logging tool 128 and/or any othersuitable location. As described in greater detail below, thecommunication link may be a hardwire link or an optical link.

In the illustrated example, the control unit 136 is computerizedequipment secured to the truck 108. However, the control unit 136 may beportable computerized equipment such as, for example, a smartphone, alaptop computer, etc. Additionally, powered controlling of theapplication may be hydraulic, pneumatic and/or electrical. In someexamples, the control unit 136 controls the operation, even incircumstances where subsequent different application assemblies aredeployed downhole. That is, subsequent mobilization of control equipmentmay not be included.

The control unit 136 may be configured to wirelessly communicate with atransceiver hub 138 of the coiled tubing reel 110. The receiver hub 138is configured for communication onsite (surface and/or downhole) and/oroffsite as desired. In some examples, the control unit 136 communicateswith the sensing system 126 and/or logging tool 128 for conveying datatherebetween. The control unit 136 may be provided with and/or coupledto databases, processors, and/or communicators for collecting, storing,analyzing, and/or processing data collected from the sensing systemand/or logging tool.

In one example, the communication link between the treatment device 122,fluid sensing system 126 and/or logging tool 128 and the surface orcontrol unit 136 may be implemented using a fiber optic or wiredtelemetry system. As such, the communication link/system may includetubing that provides and/or possesses a certain amount of stiffness incompression, similar to coiled tubing. In some such examples, a fiberoptic tube is disposed inside coiled tubing. In some examples, across-sectional area of the fiber optic tube may be small relative to aninner area defined by the coiled tubing to limit a physical influence ofthe fiber optic tube on mechanical behavior of the coiled tubing duringdeployment and retrieval, thereby preventing “bird-nesting” or bundlingwithin the coiled tubing. In some examples, optical fiber equippedcoiled tubing is deployed into and retrieved from a wellbore at agreater speed than coiled tubing with wireline.

FIG. 1B illustrates an example communication link 200 between thetreatment device 122, the fluid sensing system 126, the logging tool128, and/or the surface or control unit 136. In the illustrated example,the communication link 200 includes a tubular 105 within which a duct ortube 203 is disposed. In the illustrated example, an optical fiber 201is disposed in the tube 203. In some examples, more than one opticalfiber is disposed in the tube 203. In the illustrated example, a surfacetermination 301 and a downhole termination 207 are provided to couplethe optical fiber 201 to one or more devices or sensors 209. In someexamples, the optical fiber 201 is a multi-mode optical fiber. In otherexamples, the optical fiber 201 is a single-mode optical fiber. Thedevices or sensors 209 are, for example, gauges, valves, samplingdevices, temperature sensors, pressure sensors, distributed temperaturesensors, distributed pressure sensors, flow-control devices, flow ratemeasurement devices, oil/water/gas ratio measurement devices, scaledetectors, actuators, locks, release mechanisms, equipment sensors(e.g., vibration sensors), sand detection sensors, water detectionsensors, data recorders, viscosity sensors, density sensors, bubblepoint sensors, composition sensors, resistivity array devices andsensors, acoustic devices and sensors, other telemetry devices, nearinfrared sensors, gamma ray detectors, H₂S detectors, CO₂ detectors,downhole memory units, downhole controllers, perforating devices, shapecharges, firing heads, locators, and other devices.

FIG. 1C is a cross-sectional view of the communication link 200 of FIG.1B. Inside the tube 203, an inert gas such as nitrogen may be used tofill the space between the optical fiber or fibers 201 and the interiorof the tube 203. In some examples, the fluid is pressurized to preventthe tube 203 from buckling. In some examples, a laser-welding techniqueis performed in an enclosed environment filled with an inert gas suchas, for example, nitrogen to avoid exposing the optical fiber 201 towater or hydrogen during manufacturing. In some examples, the tube 203is constructed by bending a metal strip around the optical fiber 201 andthen welding that strip to form the tube 203. An example laser-weldingtechnique is described in U.S. Pat. No. 4,852,790, which is herebyincorporated herein by reference in its entirety. In some examples, gelincluding palladium or tantalum is inserted into an end of the tube 203to separate hydrogen ions from the optical fiber 201 duringtransportation of the communication link 200.

Materials suitable for use in the tube 203 provide stiffness to the tube203, are resistant to fluids encountered in oilfield applications,and/or are rated to withstand the high temperature and high pressureconditions found in some wellbore environments. In some examples, thetube 203 is a metallic material and the tube 203 may include metalmaterials such as, for example, Inconel™, stainless steel, or Hasetloy™.

In some examples, the tube 203 has an outer diameter of about 0.071inches to about 0.125 inches. In some examples, the tube 203 is lessthan or equal to about 0.020 inches (0.508 mm) thick. The above-noteddimensions are merely examples and, thus, other dimensions may be usedwithout departing from the scope of this disclosure

FIG. 1D illustrates another example communication link 212. In theillustrated example, the communication link 212 includes a tubular 105and a first tube 203 and a second tube 203. A first optical fiber 201 isdisposed in the first tube. A second optical fiber 201 and a thirdoptical fiber 201 are disposed in the second tube 203. In some example,the first optical fiber 201 is coupled to one of the devices 209, andthe second optical fiber 201 and the third optical fiber 201 are coupledto one or more other ones of the devices 209. In some examples, morethan one of the devices 209 may be coupled to a single optical fiber201.

FIGS. 2A-2C are schematic views of a portion of a coiled tubing system202 with a treatment device 222 and fluid sensing system 226 on a coiledtubing 214 thereof, which may be used to implement the coiled tubingsystem 102, the treatment device 122 and/or the fluid sensing system 126of FIG. 1A. FIG. 2A is a longitudinal view, partially in cross-section,depicting the fluid sensing system 226 positioned about the treatmentdevice 222. As shown, the treatment device 222 has injection ports 224for dispersing injection fluids into a well 204 as schematicallydepicted by the dashed arrows.

The injection fluid may be dispersed to treat a portion of a well 204,such as pay zone 240, to enhance production of fluid therefrom. Asillustrated in FIG. 2A, stimulation fluid, such as acid, may be injectedinto the well 204 nearby the pay (or oil producing) zone 240 by means ofthe treatment tool 222. The acid is intended for the pay zone 240, butis shown positioned downhole therefrom. Precisely positioning theinjection ports 224 against a zone of interest may be a challenging taskdue to uncertainties that may exist in target depth and/or toolposition. The sensing system 226 around the injection port 224 may betailored to measure a flow split upstream and downstream of theinjection ports 224 in the well 204. Fluid movement may be used toindicate where the pay zone 240 is located relative to the injectionport 224. Once known, the position of the treatment device 222 and theinjection ports 224 may be positioned to affect treatment as desired.

As the fluid is released from the treatment device 222, the flow of thefluid is split with an upstream portion of the fluid moving upstream anda downstream portion of the injection fluid moving downstream. Theupstream portion of the injection fluid travels upstream at a givenvelocity as indicated by the arrows labeled V1. The downstream portionof the injection fluid travels downstream at a given velocity asindicated by the arrows labeled V2. While the fluid is depicted asflowing in a specific direction, it will be appreciated that the flow ofthe fluid may vary with operating conditions.

While the example sensing system 226 illustrated in FIGS. 1 and 2A-2C isdescribed in conjunction with the coiled tubing system 102 fordetermining fluid parameters, the sensing system 226 may also be used inother fluid flow applications such as, for example, detection of fluidcross-flow between zones, production logging (e.g., for single phasevelocity, or in conjunction with Flow Scanner Imaging (FSI)complementary to a spinner in a low velocity range), downhole or surfacetesting in conjunction with use of a flowmeter (e.g., low speed Venturibased flowmeter applications), leakage detection (e.g., with dynamicseals), with other tools where flow velocity measurements is desired,among others. The sensing system 226 may be positioned on any surface,downhole and/or other movable equipment, such as a downhole tool, and/orin fixed equipment, such as a casing (not shown).

The sensing system 226 is depicted in FIG. 2A as having a plurality ofsensor elements 242 a,b positioned about the treatment device 222. Insome examples, one or more sensor elements 242 a,b are positioned aboutthe coiled tubing system 102 to perform fluid and/or other downholemeasurements. In some such examples, the sensor elements 242 a,b arepositioned about the injection port(s) 224 to measure fluid parameters.The fluid measured is the injection fluid dispersed from the treatmentdevice 222, but may also include other fluids in the well (e.g., water,hydrocarbons, gases, etc.) that mix with the injection fluid as it isdispersed.

An upstream portion of the sensor elements 242 a are depicted as beingpositioned on the treatment device 222 a distance upstream therefrom. Adownstream portion of the sensor elements 242 b are depicted as beingpositioned on the treatment device 222 a distance downstream therefrom.The upstream sensor elements 242 a and/or the downstream sensor elements242 b may be arranged radially about the treatment apparatus 222. In theillustrated example of FIG. 2B, the sensor elements 242 a,b arepositioned at various radial locations x,y,z about the treatmentapparatus 222. While a specific configuration for the sensor elements242 a,b is depicted in FIGS. 2A and 2B, it will be appreciated that oneor more sensor elements may be positioned at various locations(longitudinally and/or radially) about the coiled tubing system 202and/or well 204.

At least some of the sensor elements 242 a,b are capable of sensingfluid parameters, such as fluid direction and velocity. In someexamples, more than one of the sensor elements 242 a,b may be capable ofmeasuring the fluid parameters. In some examples, at least one of thesensor elements 242 a for measuring fluid parameters is positionedupstream from the injection port 224, and at least one of the sensorelements 242 b for measuring fluid parameters is positioned downstreamfrom the injection port 224. In this configuration, the measurements ofthe upstream and the downstream fluid sensors 242 a,b may be compared todetermine fluid parameters, such as fluid direction and/or fluidvelocity. The ratio between upper and lower velocities and fluiddirection obtained from measurements of the upstream and downstreamsensing elements 242 a,b may be used to generate real-time monitoring ofwhere the fluid is flowing during the treatment, as will be describedfurther herein. Other downhole parameters may also optionally bemeasured with the fluid sensing system 226 and/or other sensorspositioned about the well.

Comparison of multiple sensing elements 242 a,b may be used to accountfor differences in measurements taken by the various sensing elements242 a,b. In some examples, multiple sensing elements 242 a,b are used toprovide sufficient redundancy and confidence in the measurement results.This redundancy may also reduce the severity of impact where one or moresensor elements 242 a,b fails, such as in harsh downhole environmentsinvolving the use of acids. The multiple sensing elements 242 a,b mayalso be used to generate fluid direction and/or velocity information. Insuch cases, at least one upstream sensor element 242 a and at least onedownstream sensor element 242 b may be used. In some examples,additional sensor elements 242 a,b are provided to enhance reliabilityof the values generated.

In some examples, it may be useful to consider the position of thesensing element 242 a,b about the treatment tool 222. The number ofarrays (or sets of sensing elements 242 a,b), as well as the number ofsensing elements 242 a,b per array, may vary. As shown in FIG. 2A, thesensing elements 242 a,b are positioned upstream and downstream tomeasure fluid as it passes upstream and downstream from the injectionports 224. In some examples, when using corresponding upstream anddownstream sensing elements 242 a,b, the corresponding sensing elements242 a,b, are positioned at equal distances from the injection port 224.In some examples, corresponding sensing elements 242 a,b are identicallymatched. Matched sensing elements may be spaced at equal distances.

In the illustrated example, multiple sensing elements 242 a,b are alsopositioned about the circumference of the tool at 90-degree intervals x,y, and z as shown in FIG. 2B. As shown in FIG. 2B, the sensing elements242 b are positioned at radial locations x, y and z about the treatmentdevice 222. The sensing element 242 b at position x is against a wall205 of the well 204. The azimuthal arrangement of sensing elements 242a,b at positions x, y, and z provides redundancy in case one side ofmeasurements is impeded.

An issue may appear when the tool body (e.g., the treatment tool 222) iseccentric (or not concentric) with the well 204 as shown in FIG. 2B. Inthe illustrated example, the sensing element 242 b _(x) located closerto the wall 205 of the well 204 may read a lower flow value than thesensing elements 242 b _(y), 242 b _(z) positioned farther from thewall. In such cases, it may be desirable to ignore or removemeasurements from potential obstructed sensing elements, such as thesensing element 242 b _(x).

As shown in FIG. 2B, the sensing elements 242 b are positioned on anouter surface 223 of the treatment tool 222. The sensing elements 242 bmay be flush with the outer surface 223, recessed below the outersurface 223 or extended a distance therefrom. In some examples, thesensing elements 242 b are positioned such that each sensing element 242b contacts fluid for measurement thereof, but remains protected. Toprevent damage in harsh downhole conditions, protrusion of the sensingelements 242 b from the treatment tool may be reduced. As shown in FIG.2C, the sensing elements 242 b may also be positioned inside thetreatment tool 222, for example, on an inner surface 225 thereof.

FIGS. 2D and 2E illustrate other portions of the coiled tubing system202 including the fluid sensing system 226, which may be used toimplement the example coiled tubing system 102 of FIG. 1A. In FIG. 2D,the example sensing system 226 is disposed at a lower end of the coiledtubing 114.

In FIG. 2E, the example sensing system 226 is disposed between thelogging tool 128 and the treatment tool 122. In the illustrated example,the logging tool 128 is disposed above the sensing system 226 and thetreatment tool 122 is disposed below the sensing system 226 in theorientation of FIG. 2E. In some examples, the fluid enters the well 104as shown by arrows V3. In other examples, the sensing system 226 isdisposed at one or more other locations on the coiled tubing 114.

FIG. 3 is a graph 350 depicting sensor data taken from the examplesensing elements 242 b of FIG. 2B. The graph 350 plots flow velocity(x-axis) as a function of sensor output (y-axis) for sensing elements242 b _(x), 242 b _(y), and 242 b _(z) at positions x, y and z,respectively. As depicted by the graph 350, the flow velocity of thesensing elements 242 b _(y) and 242 b _(z) at positions y and z aredifferent from the flow velocity of the sensing element 242 b _(x) atposition x. In other words, readings of the top sensing element 242 b_(z) and the 90-degree sensing element 242 b _(y) are substantiallyconsistent in determining the flow velocity. However the bottom sensingelement 242 b _(x) has a flow velocity that is lower.

The graph 350 indicates that the sensing element 242 b _(x) at positionx is pressed against the wall 205 of the well 204 and is unable toobtain proper readings. Thus, the measurements depicted by line 242 b_(x) taken by sensing element 242 b at position x may be disregarded.The measurements depicted as lines 242 b _(y) and 242 b _(z) taken bysensing elements 242 b at positions y and z, respectively, may becombined using conventional analytical techniques (e.g., curve fitting,averaging, etc.) to generate an imposed flow 244. Thus, by placingseveral sensing elements 242 a,b azimuthally around the circumference ofa tool and detecting the lowest reading sensing element (e.g., 242 b_(x)), the azimuth of a flow obstruction may be determined. The sensingelement located opposite to the lowest-reading sensing element (e.g.,242 b _(y)), or combinations of other sensing elements, may then be usedto perform the flow measurement.

FIGS. 4A and 4B are schematic views of sensing elements 442 p and 442 qusable as the sensing elements 242 a,b of FIGS. 2A and 2B. Each of thesensing elements 442 p,q has a heater 454 p,q and a sensor 456 p,q,respectively, positioned in a sensor base 452. In the illustratedexample, the sensor 456 p,q is a temperature sensor (or temperaturesensor) capable of measuring fluid temperature.

In some examples, the sensor elements 442 p,q are calorimetric type flowsensors (or flow meters) that have two sensing elements such as, forexample, a sensor for velocity measurement (scalar sensor) and a sensorfor directional measurement (vector sensor). The heater 454 p,q and thetemperature sensor 456 p,q interact to operate as velocity (or scalar)and directional (or vector) sensors.

To determine fluid velocity, the sensing elements 442 p,q act ascalorimetric sensors. The heater 454 p,q (or hot body) of each sensorelements 442 p,q is placed in thermal contact with the fluid in the well104. The rate of heat loss of the heater 454 p,q to the fluid is afunction of the fluid velocity as well as thermal properties. A heatdissipation rate of the heater 454 p,q may be measured, and a flowvelocity can be determined for a known fluid. The heater 454 p,qgenerates heat (e.g., from electricity), and dissipates the heat to thefluid in contact. The rate of heat generation and the temperature may bereadily measurable during operation.

The temperature sensor 456 p,q may be used to monitor ambienttemperature of the fluid, while the heater 454 p,q measures its owntemperature during heating. The difference between the temperature ofthe heater 454 p,q and the ambient temperature of the fluid is definedas temperature excursion. The temperature excursion, ΔT, may be writtenas follows:

ΔT=T _(h) −T _(a).  Equation (1)

In Equation 1, T_(a) represents the ambient temperature of the fluid asmeasured by the temperature sensor; T_(h) represents the temperature ofthe heater; and the temperature excursion is proportional to the heaterpower at a given flow condition. A thermal property between the heaterand the fluid such as, for example, thermal conductance, G_(th), may becalculated according to following expression:

$\begin{matrix}{G_{th} = {\frac{P}{T_{h} - T_{a}} = {\frac{P}{\Delta \; T}.}}} & {{Equation}\mspace{14mu} (2)}\end{matrix}$

In Equation 2, P represents the heater power in steady state. Theinverse of this proportionality (or the thermal conductance) correlatesthe flow velocity V_(flow) because V_(flow) is a function of G_(th). Asprovided by Equation 1, the thermal conductance is determined from threequantities: P (the heater power), T_(h) (the temperature of the heater)and T_(a) (the temperature of the fluid ambient). The quantities may bemeasured in steady state. Theoretically, the amount of power ortemperature excursion used during measurement is immaterial to resultantthermal conductance. However, power and temperature excursion may affectaccuracy because physical measurements have limits. In some cases, suchas the configuration of FIG. 4B, a ΔT of a few degrees in Kelvin (K) maybe considered appropriate.

In other examples, other thermal properties such as, for example, anormalized power dissipation are calculated to determine the flowvelocity. The normalized power dissipation may be calculated accordingto the following expression:

$\begin{matrix}{\frac{P}{S( {T_{h} - T_{a}} )}.} & {{Equation}\mspace{14mu} (3)}\end{matrix}$

In Equation 3, the normalized power dissipation is calculated bydividing the power of the heater by the temperature excursion and anarea of a heating surface of the sensor, S.

The measurements taken by the calorimetric sensing elements 454 p,q maybe used obtain the heater-fluid thermal conductance, the normalizeddissipated power, and/or other thermal properties. A measurementtechnique may involve either constant excursion or constant power. Forthe constant excursion technique, power sent to the heater may beregulated by electronics (e.g., the control unit 136) such that theheater temperature may be maintained at a constant excursion above thefluid ambient temperature. In steady state, the power measured ismonotonically related to the thermal conductance, the normalized powerdissipation, and/or other thermal properties. For the constant powertechnique, the heater may be supplied with a constant and predeterminedpower, while the heater temperature T_(h) varies and may be determinedby flow velocity.

FIG. 5A is a graph 657 depicting a flow response of a calorimetricsensor, such as the sensing elements 442 a,b depicted in FIGS. 4A and4B. The resulting thermal conductance verses flow curve 658 demonstratesthat thermal conductance is non-linear relative to the flow velocity.However, the thermal conductance verses flow curve 658 is monotonic.Therefore, a correlation can be established to invert the measurement,and the flow velocity can be obtained as described in conjunction withEquations 1-3.

The measurement of flow velocity is a measurement of the thermalconductance, the normalized power dissipation, and/or other thermalproperties between the heater 454 p,q and the fluid. The measurement ofthermal conductance and/or the normalized power dissipation may bedetermined with constant temperature excursion (ΔT) or constant heaterpower. The constant temperature excursion may regulate temperature. Theconstant heater power may regulate power. Either measurement techniquemay involve the heater 454 p,q and the temperature sensor 456 p,q.

Referring back to FIGS. 4A and 4B, the sensing elements 442 p,q may alsoact as scalar sensors to determine fluid direction. In the illustratedexample, the sensing elements 442 p,q are capable of acting as bothcalorimetric sensors for determining fluid velocity and vector sensorsfor measuring fluid direction. Calorimetric sensors may be unable todetermine fluid direction. In such examples, the calorimetric sensorsmay respond to fluid velocity regardless of direction. Fluid directionmay be acquired by a second measurement, such as by using vector sensorscapable of fluid direction detection. Fluid direction may also beacquired by, for example, the sensing elements 442 p,q of FIGS. 4A and4B configured for measurement of both fluid velocity and direction.Physics that enables directional detection may also involve detection ofasymmetry in temperature between upstream and downstream sensingelements (e.g., caused by heat from the heater 454 p of the upstreamsensing element), such as the upstream sensing elements 242 a and thedownstream sensing elements 242 b of FIG. 2A.

FIGS. 4A and 4B depict configurations of the sensing element 442 p,qcapable of detecting both fluid flow rate and direction. FIG. 4A depictsa thermocouple (TC) sensing element 442 p. FIG. 4B depicts a dualsensing element 442 q. The base 452 for each sensing element 442 p,q issized for hosting the heater 454 p,q, the sensor 456 p,q and/or otherdevices therein.

In some examples, the base 452 has a minimum thickness, or is recessedin the downhole tool, to prevent damage in the well 104. The sensor base452 is positionable downhole, for example, on the treatment device 122,222 and/or the coiled tubing 114, 214 (FIGS. 1, 2A, 2B). The base 452may be round as shown in FIG. 4A or rectangular as shown in FIG. 4B. Thebase 452 may be made of epoxy, PEEK molding and/or any other material.

The heater 454 p,q and the temperature sensor 456 p,q may be positionedin close proximity in base 452, but are thermally isolated from eachother. In the illustrated example, because the heater 454 p,q creates atemperature gradient in the fluid, the temperature sensor 456 p,q isprovided with sufficient thermal isolation from the heater 454 p,q toprevent the temperature sensor 456 p,q from being disturbed by the heatflux of the heater 454 p,q or thermally coupling with the heater 454p,q, which may result in an erroneous measurement value. The temperaturesensor 456 p,q may optionally be positioned in a separate package spacedfrom the heater 454 p,q.

The TC sensing element 442 p of FIG. 4A is depicted as having a pair ofTC junctions (or sensors) 456 p _(1,2) on either side of a heating pad(or heater) 454 p. The TC junctions 456 p _(1,2) are linked by a metalwire 460. Each TC junction 456 p _(1,2) has a TC pad with leads 462 a,bextending therefrom. In some examples, the leads 462 are also wiresoperatively coupled to a controller 436 for operation therewith.

The TC junctions 456 p positioned on either side of the heater 454 p maybe used to detect a temperature imbalance therebetween, and convert itinto a TC voltage. A small voltage is present if the two TC junctions456 p _(1,2) are at a different temperatures. The TC junctions 456 p_(1,2) are positioned very close to the heater 454 p (one on each side)for maximum contrast of temperature. At zero flow, the heater 454 p mayheat up both TC junctions 456 p _(1,2). However, the heating does notproduce voltage.

Two metal pads 464 p are depicted as supporting the TC junctions 456 p_(1,2). The metal pads 464 p may be provided to improve the thermalcontact between the TC junctions 456 p _(1,2) and the fluid. The metalpads 464 p may be useful in cases where the TC junctions 456 p _(1,2)are of a small size. The metal pads 464 p and the TC junctions 456 p_(1,2) may be held together by thermal adhesives such as silver epoxiesor any other thermally conductive adhesives. The metal pads 464 p arepositioned in alignment with the heater 454 p, thereby defining aflowline 466 p along the sensing element 442 p as indicated by thearrow.

TC voltage (y-axis) as a function of flow velocity (x-axis) is show in agraph 659 of FIG. 5B. The graph 659 exhibits an odd function of the flowvelocity measured by the TC junctions 456 p _(1,2). The magnitude of amaxima near zero flow tapers off gradually with increasing velocity. Atzero crossing, the TC signal output undergoes an abrupt change inpolarity from negative to positive as indicated by curves 661 a,b,respectively. This change in signal polarity may be used to detect thefluid direction as described in greater detail below.

The temperature profile along a flow stream of, for example, the sensingelement 442 p is shown schematically in FIG. 6. FIG. 6 is a graph 663depicting temperature (y-axis) versus velocity (x-axis). As depicted bythis graph, the heater 454 p generates a constant heat T_(h) measurableby the TC junction 456 p _(1,2) on either side thereof. Heat from theheater 454 p is carried downstream by the fluid forming a hot stream.The velocity V1, V2 and V3 are measured at, for example, different timeintervals. Visibility of the thermal gradient may depend on thevelocity. The thermal gradient between upstream and downstream isdetectable with the sensor element 442 p. This creates a temperaturecontrast between the upstream and downstream TC junctions 456 p _(1,2).This indicates that the flow is moving towards the TC junctions 456 p ₂,thereby indicating fluid flow direction. By detecting asymmetry betweenthe TC junctions 456 p _(1,2), the fluid direction can be determined asindicated by the arrow.

The dual-element sensing element 442 q of FIG. 4B is depicted as havingtwo identical elements (sensors/heaters) 456 q/454 q. Thesensors/heaters 456 q/454 q are depicted as Element M and Element N inthe sensing element 442 q. In some examples, the heater 454 q and thesensor 456 q (and, therefore, Elements M and N) are interchangeable infunction and operation. In some such cases, the sensor 456 q is capableof performing the functions of the heater and the heater 454 q iscapable of performing the functions of the sensor. The Elements M and Nare operatively linked via links 455 to the controller 436 for operationtherewith.

In some examples, a desired measurement may be operated inself-referenced mode in which a single Element M or N plays a dual role,both as heater and as temperature sensor. In some such cases, the heaterand the temperature sensor may utilize a time multiplexing technique. Insome examples, the role of the heater 454 q and temperature sensor 456 qmay be reassigned at anytime. This measurement scheme may be used toprovide flexibility in designing and/or operating the sensor element 442q, which may be tailored to a particular application.

An asymmetry of temperature between the identical Elements M and N isdetectable by the dual-element sensor 442 q. The two identical ElementsM and N are positioned along a line of flow of the fluid as indicated bythe arrow. The Elements M and N may be positioned in close proximity,for example, within the same base (or package) 452.

Measurement by the sensor element of FIG. 4B may be achieved usingvarious methods. A first method involves measuring the heater power inflow using Element M as the heater and Element N as the temperaturesensor. After a stable reading is attained, the roles of Elements M andN interchange and the measurement is repeated. Comparing the power ofthe two measurements, fluid direction can be ascertained. The heaterthat consumes more power is located upstream, provided that the flowdoes not vary in the meantime. A second method that may be used involvesmeasuring by heating both elements M and N simultaneously with the sameamount of power. The measurements of each element may be compared.Whichever element reveals a higher temperature is downstream in thedirection of the fluid flow. A third method that may be used involveswatching the temperature of Element M while switching on and off ElementN at a certain power level. If an alteration of temperature is noticed,Element N may be assumed to be upstream of Element M. No change maysuggest otherwise.

With the first two methods, where quantities are compared acrossElements M and N, a good match of characteristics of the two elements M,N reduces potential errors. The match of elements may be achieved bycalibration and normalization. The third method, on the other hand, maybe used without as good of a match. Dual-element sensors are usable, forexample, for bi-directional flow.

When the temperature sensor 456 p,q and the heater 454 p,q of FIGS. 4Aand 4B reside in the same package (for instance, due to spaceconstraint), the temperature sensor 456 p,q is positioned upstream ofthe heater 454 p,q (or element M is upstream of Element N). If flow goesin both directions, the temperature sensor 456 p,q and heater 454 p,q(or Elements M and N) may be positioned in a side-by-side (or flowline)configuration in line with the flow of the fluid as shown in the sensingelements 442 p,q of FIGS. 4A and 4B.

While FIG. 4A depicts a single heater 454 p with a pair of TC junctions456 p and FIG. 4B depicts a single heater 454 p with a singletemperature sensor 456 q, other examples employ multiple heaters 454 p,qand/or sensors 456 p,q. Additional sensors and/or other devices may beincorporated into the sensing elements 442 p,q and/or used incombination therewith. In sensor systems including multiple heaters 454p,q, one temperature sensor 456 p,q can serve multiple heaters 454 p,q.Some multi-elements sensors have more than two elements (e.g., M, N, P,D . . . ). As shown in FIG. 4B, a third element O may be provided. Inanother method of measurement, the three or more elements (e.g., M, N,O) may be used to detect fluid direction by heating a middle element andcomparing the temperature between upstream and downstream elementsthereabout.

As shown, the sensing elements 442 p,q of FIGS. 4A and 4B (and/or thesensors, heaters, elements and/or other components used therein and/ortherewith) are operatively coupled to the controller 436 for providingpower, collecting data, controlling and/or otherwise operating thesensing element 442 p,q. The controller 436 may be, for example, thelogging tool 128, the control unit 136 and/or other electronics capableof providing power, collecting data, controlling and/or otherwiseoperating the temperature sensors 456 p,q, heater 456 p,q and/or otherelements of the sensing elements 442 p,q. The power sources may bebatteries, power supplies and/or other devices internal to and/orexternal to the sensing elements. In some cases, other devices such asthe logging tool 128 of FIG. 1A may provide power thereto. Suchelectronic devices may be internal and/or external to the sensingelements. Communication devices may be provided to wire and/orwirelessly coupled the sensing elements to downhole and/or surfacecommunication devices for communication therewith. In some cases,communication devices, such as transceivers may be provided in thesensing elements. In other cases, the sensing elements may be linked tothe logging tool 128 (FIG. 1A) or other devices for communication asdesired.

The sensing elements are also operatively coupled to and/or incommunication with databases, processors, analyzers, and/or otherelectronic devices for manipulating the data collected thereby. Thepower, electronic and/or communication devices may be used to manipulatedata from the sensing elements, as well as other sources. The analyzeddata may be used to make decisions concerning the wellsite and operationthereof. In some cases, the data may be used to control the welloperation. Some such control may be done automatically and/or manuallyas desired.

While elements of the heater and the temperature sensor may bephysically identical, the sensor can have a variety of types, formsand/or shapes. FIG. 7 depicts the sensor 770 usable as an element of thesensor elements 454 p,q of FIGS. 4A and/or 4B. FIG. 7 depicts the sensor770 usable as the heater 454 q and/or the temperature sensor 456 q, aselements M, N and/or O, or in combination therewith. A shown, the sensor770 is positionable in the base 452. The sensor 770 may be operativelycoupled to the controller 436 via wires 774 for operation therewith inthe same manner as previously described for the sensor elements 442 p,q.

The example sensor 770 of FIG. 7 is an RTD type sensor with a resistancethat varies with temperature. In some examples, the sensor 770 is usedfor temperature sensing purposes. However, the sensor 770 may generateheat when current passes through the sensor 770. Thus, the examplesensor 770 can be used both as a heater and a temperature sensor (e.g.,454 p,q and 456 p,q of FIG. 4B).

A thin-film type RTD capable of use as both a heater and temperaturesensor may be used so that it can interchangeably operate as the ElementM, N and/or O of FIG. 4B. As shown in FIG. 7, the sensor 770 positionedin the base 452 has a front surface (or contact surface) 772positionable adjacent the fluid for taking measurements therefrom. Insome examples, the sensor 770 employs platinum in the form of eitherwire or thin film (or resistor) 774 deposited on a heat-conductivesubstrate 776, such as sapphire or ceramic. The wire 774 is positionedin the film 776 and extends therefrom for operative linkage with thecontroller 436. The heat-conductive substrate 776 may be adhered orbonded to a thin pad 778 (made of, for example, Inconel or ceramicsubstrate) by a thermally conductive adhesive 780, such as silver epoxy,or by brazing. In some examples, such bonding provides low thermalresistance.

In the illustrated example, the sensor 770 is wrapped in protectivepackaging, but they may differ by thermal mass and, hence, responsetime. The shape of the pad 778 may be square, circular or any othershape capable of supporting the RTD in the base 452. In some examples,the pad 778 has a dimension of about 10 mm (or more or less), and athickness sufficient for mechanical viability. The thickness andmaterial selected may determine the performance of heater-fluid thermalcontact.

The example sensor 770 may be configured with a large surface area forcontact with the fluid and/or large thermal mass for passage of heattherethrough. A larger thermal mass may result in a relatively slowermeasurement response. However, the thermal mass may also assist inreducing (e.g., averaging out) spurious variations in readings caused byturbulence. Sensor electronics may also be provided to reduce spuriousvariations.

The sensor 770 and/or the sensing element 442 q may be configured in asurface (or non-intrusive) form with a low profile (or thickness) asshown in FIGS. 7 and 4B. The sensor 770 and/or the sensing element 442 qmay be positionable downhole via a downhole tool (e.g., coiled tubingsystem 102 of FIG. 1A) extending a small distance (if any) therefrom.This low profile or non-intrusive surface form may be provided to reducethe disturbance to the fluid flowing across the sensor, while stillallowing for measurement of the fluid. Moreover, the low profile surfaceform may also be configured to limit the amount of protrusion from thedownhole the tool and, therefore, potential damage thereto.

Another example using the previously described sensor elements 242 andapparatus is shown in FIG. 8. FIG. 8 depicts an example apparatus toprovide a method of determining downhole fluid parameters and fluidlevels. For example, the logging tool 128 along with the sensors 242and/or sensing system 226 may be disposed downhole as or along with anykind of other tool, and may be lowered/raised into/from the well 104 asshown by the arrows. As such, the tool may transverse through multiplelayers of fluid, such as for example L1 and L2 which may of course havevarying thermal properties and densities. For example, these propertieswill vary greatly between gas, mud, oil, water, brine, etc. Therefore,as the tool is traversed at a constant speed and as the tool enters thedifferent layers L1, L2, the response of the sensors 242 and/or sensingsystem 226 will greatly change depending on the fluid. Therefore, aboundary B between the layers may be determined. Additionally oralternatively, the sensors 242 and/or sensing system 226 information canalso be used to identify the fluids located in the layers. Furthermore,with the addition of a depth measurement device, a relative or absolutelocation of the boundary B and the layers L1, L2 can be made.

FIGS. 9, 10 are flowcharts representative of example methods disclosedherein. At least some of the example methods of FIGS. 9, 10 may becarried out by a processor, the logging tool 128, the controller 436and/or any other suitable processing device. In some examples, at leastsome of the example methods of FIGS. 9, 10 are embodied in codedinstructions stored on a tangible machine accessible or readable mediumsuch as a flash memory, a ROM and/or random-access memory RAM associatedwith a processor. Some of the example methods of FIGS. 9, 10 may beimplemented using any combination(s) of application specific integratedcircuit(s) (ASIC(s)), programmable logic device(s) (PLD(s)), fieldprogrammable logic device(s) (FPLD(s)), discrete logic, hardware,firmware, etc. Also, one or more of the operations depicted in FIGS.10-11 may be implemented manually or as any combination of any of theforegoing techniques, for example, any combination of firmware,software, discrete logic and/or hardware.

Further, although the example methods are described in reference to theflowcharts illustrated in FIGS. 9, 10, many other methods ofimplementing the example methods may be employed. For example, the orderof execution of the blocks may be changed, and/or some of the blocksdescribed may be changed, removed, sub-divided, or combined.Additionally, any of the example methods of FIGS. 9, 10 may be carriedout sequentially and/or carried out in parallel by, for example,separate processing threads, processors, devices, discrete logic,circuits, etc.

FIG. 9 illustrates an example method 900 disclosed herein that may beused to determine one or more fluid parameters. At block 1002, adownhole system such as, for example, the coiled tubing system 100 ofFIG. 1A is deployed into a well with a sensor (e.g., one of the examplesensor elements 242 a,b of FIG. 2A) thereon. In some examples, thesensor includes a heater (e.g., the example heater 454 of FIG. 4, theexample RTD sensor 770 of FIG. 7) and a temperature sensor (e.g., theexample temperature sensor 456 of FIG. 4, the example RTD sensor 770 ofFIG. 7). At block 904, fluid is injected from the downhole system intothe well via an injection port (e.g., the example injection port 224 ofFIG. 2) of the downhole system.

At block 906, a first measurement (e.g., a temperature of the fluid) istaken with the temperature sensor. At block 908, a second measurement(e.g., power dissipated via the heater, a temperature of the heater,etc.) is taken with the heater. At block 910, a fluid parameter (e.g., afluid velocity, a direction of fluid flow) is determined based on thefirst measurement and the second measurement. At block 912, the fluidparameter is analyzed. In some examples, the measurements and/or theparameter are stored, processed, reported, and/or manipulated, etc.

FIG. 10 illustrates an example flow chart that may be used to implementthe examples disclosed herein. The example process 1000 may begin bydeploying a downhole apparatus and/or tool into a wellbore (block 1002).At a first position of the wellbore, a sensor of the downhole tool mayobtain a first response of a first fluid such as, for example, a firstthermal property and/or velocity (block 1004). A processor and/orcontrol unit may compare the first response and/or thermal property toresponses and/or thermal properties of reference fluids (block 1006).Based on the comparison, a fluid type of the first fluid may bedetermined (block 1008). In some examples, the fluid includes gas, mud,oil, water and/or brine. In some examples, the processor and/or controlunit is partially or wholly implemented downhole (e.g., within thedownhole tool). In some examples, the processor and/or control unit ispartially or wholly implemented uphole (e.g., within the control unit136).

The downhole tool may then be moved from the first position of thewellbore to a second position of the wellbore (block 1010). In someexamples, the downhole tool is moved between the first and secondpositions at a substantially constant rate. At the second position ofthe wellbore, the sensor of the downhole tool may obtain a secondresponse of a second fluid such as, for example, a second thermalproperty and/or velocity (block 1012). A processor and/or control unitmay compare the second response and/or thermal property to responsesand/or thermal properties of reference fluids (block 1014). Based on thecomparison, a fluid type of the second fluid may be determined (block1016). At block 1018, the processor and/or control unit determines thepresence of a boundary based on the first and second responses and, ifidentified, a relative position of the boundary may be determined basedon the first and second positions, for example (blocks 1018, 1020). Insome examples, the presence of the boundary is determined based oncomparing and identifying a difference between the first and secondresponses and/or thermal properties. At block block 1022, a profile ofthe formation may be generated based the layers, the fluid types, etc.,identified (block 1022).

An example method includes deploying a downhole apparatus into awellbore. The downhole apparatus includes a sensor having a heater and atemperature sensor. The method also includes traversing the downholeapparatus through the wellbore and obtaining a first response with thesensor in a first position of the wellbore. The method also includesobtaining a second response with the sensor in a second position ofwellbore and determining a presence of a boundary between the first andsecond positions based on the first and second responses.

In some examples, the method includes determining a fluid type based onthe first or second responses. The fluid type may include one or more ofgas, mud, oil, water, or brine. In some examples, the method includesdetermining a relative position of the boundary based on the first andsecond positions. In some examples, the first position is associatedwith a first fluid layer and the second position is associated with asecond fluid layer.

Another example method includes determining a first thermal property ofa first fluid at a first wellbore position via a sensor of a downholetool. The sensor includes heater and a temperature sensor. The methodalso includes determining a second thermal property of a second fluid ata second wellbore position via the sensor. The method includes comparingthe first and second thermal properties to identify a differencetherebetween associated with a boundary.

In some examples, the first thermal property is a first velocity and thesecond thermal property is a second velocity. In some examples, thesensor includes a calorimetric sensor. In some examples, whereindetermining the first velocity of the fluid at the first wellboreposition includes heating the fluid and determining a temperature of thefluid. In some examples, the method also includes determining a thermalconductance between the heater and the fluid. In some examples, themethod also includes moving the downhole tool from the first wellboreposition to the second wellbore position. In some examples, moving thedownhole tool comprises moving the downhole tool at a substantiallyconstant rate. In some examples, the method also includes generating aprofile of the formation based on first and second velocities.

Another example method includes determining a first thermal property ofa first fluid at a first wellbore position via a sensor of a downholetool. The sensor includes a heater and a temperature sensor. In someexamples, the method includes comparing the first thermal property withthermal properties of reference fluids determining a fluid type of thefirst fluid based on the comparison. In some examples, the method alsoincludes determining a second thermal property of a second fluid at asecond wellbore position via the sensor. The method also includescomparing the second thermal property with the thermal properties of thereference fluids and determining a fluid type of the second fluid basedon the comparison.

In some examples, the method also includes comparing the first andsecond thermal properties to identify a difference therebetweenassociated with a boundary. In some examples, the method also includesdetermining a relative position of the boundary based on the first andsecond positions. In some examples, the method also includes generatinga profile of a formation based on first and second thermal properties.In some examples, the method also includes moving the downhole tool fromthe first wellbore position to the second wellbore position. In someexamples, the moving the downhole tool includes moving the downhole toolat a substantially constant rate.

Although only a few example embodiments have been described in detailabove, those skilled in the art will readily appreciate that manymodifications are possible in the example embodiments without materiallydeparting from this disclosure. Accordingly, such modifications areintended to be included within the scope of this disclosure as definedin the following claims. In the claims, means-plus-function clauses areintended to cover the structures described herein as performing therecited function and not only structural equivalents, but alsoequivalent structures. Thus, although a nail and a screw may not bestructural equivalents in that a nail employs a cylindrical surface tosecure wooden parts together, whereas a screw employs a helical surface,in the environment of fastening wooden parts, a nail and a screw may beequivalent structures. It is the express intention of the applicant notto invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of theclaims herein, except for those in which the claim expressly uses thewords ‘means for’ together with an associated function.

The Abstract at the end of this disclosure is provided to comply with 37C.F.R. §1.72(b) to allow the reader to quickly ascertain the nature ofthe technical disclosure. It is submitted with the understanding that itwill not be used to interpret or limit the scope or meaning of theclaims.

What is claimed is:
 1. A method, comprising: deploying a downholeapparatus into a wellbore, the downhole apparatus comprising a sensorhaving a heater and a temperature sensor; traversing the downholeapparatus through the wellbore; obtaining a first response with thesensor in a first position of the wellbore; obtaining a second responsewith the sensor in a second position of wellbore; and determining apresence of a boundary between the first and second positions based onthe first and second responses.
 2. The method of claim 1, furthercomprising determining a fluid type based on the first or secondresponses.
 3. The method of claim 2, wherein the fluid type comprisesone or more of gas, mud, oil, water, or brine.
 4. The method of claim 1,further comprising determining a relative position of the boundary basedon the first and second positions.
 5. The method of claim 1, wherein thefirst position is associated with a first fluid layer and the secondposition is associated with a second fluid layer.
 6. A method,comprising: determining a first thermal property of a first fluid at afirst wellbore position via a sensor of a downhole tool, the sensorcomprising a heater and a temperature sensor; determining a secondthermal property of a second fluid at a second wellbore position via thesensor; and comparing the first and second thermal properties toidentify a difference therebetween associated with a boundary.
 7. Themethod of claim 6, wherein the first thermal property comprises a firstvelocity and the second thermal property comprises a second velocity. 8.The method of claim 6, wherein the sensor comprises a calorimetricsensor.
 9. The method of claim 6, wherein determining the first velocityof the fluid at the first wellbore position comprises heating the fluidand determining a temperature of the fluid.
 10. The method of claim 6,further comprising determining a thermal conductance between the heaterand the fluid.
 11. The method of claim 6, further comprising moving thedownhole tool from the first wellbore position to the second wellboreposition.
 12. The method of claim 11, wherein moving the downhole toolcomprises moving the downhole tool at a substantially constant rate. 13.The method of claim 6, further comprising generating a profile of theformation based on first and second velocities.
 14. A method,comprising: determining a first thermal property of a first fluid at afirst wellbore position via a sensor of a downhole tool, the sensorcomprising a heater and a temperature sensor; comparing the firstthermal property with thermal properties of reference fluids; anddetermining a fluid type of the first fluid based on the comparison. 15.The method of claim 14, further comprising: determining a second thermalproperty of a second fluid at a second wellbore position via the sensor;and comparing the second thermal property with the thermal properties ofthe reference fluids; and determining a fluid type of the second fluidbased on the comparison.
 16. The method of claim 15, further comprisingcomparing the first and second thermal properties to identify adifference therebetween associated with a boundary.
 17. The method ofclaim 16, further comprising determining a relative position of theboundary based on the first and second positions.
 18. The method ofclaim 15, further comprising generating a profile of a formation basedon first and second thermal properties.
 19. The method of claim 15,further comprising moving the downhole tool from the first wellboreposition to the second wellbore position.
 20. The method of claim 19,wherein moving the downhole tool comprises moving the downhole tool at asubstantially constant rate.